Comments on this proposal are being reviewed, and alternative suggestions will be considered.

Question: In your view, could this change detrimentally affect otherwise prudent business decisions on placement of electrical plants? For example, would this unnecessarily bias utility decisions towards building plants near load centers?

Answer: The exchange program was intended to be neutral with respect to the decision-making processes of the utilities participating in the program. Nonetheless, it will have some effect on decisionmaking since any change that has an impact on the subsidy a utility receives will to some extent influence that utility's decision-making processes. However, the proposed change regarding allowable transmission cost should not unnecessarily bias utility decisions, nor is it intended to become prevailing factor in or prejudice these decisions.

Question: Explain the need for adjustments in the treatment of income taxes.

Answer: The actual taxes paid by a utility are based on a rate of return authorized by the specific jurisdiction governing the utility. To permit a standard, consistent method for calculating taxes, BPA has proposed to use the utility's effective rate. As a consequence, the tax expense of the utility will differ from the actual taxes paid by the utility, but a uniformity of treatment will be achieved. Comments on this proposal are being received.

Question: Please respond to the criticism that the proposed change would allow BPA to take advantage of accelerated depreciation and investment tax credit provisions while ignoring a tax law requirement to normalize such benefits?

Answer: The criticism is unfounded. Normalization of those benefits is included in the proposed methodology because the effective tax rate includes deferred tax and normalized investment tax credit adjustments.

Question: Why change to using the "historical" data from the FERC Form 1 document for Average System Cost calculations?

Answer: The use of historical or actual data was proposed to achieve consistency with the uniform cost approach proposed in the Average System Cost Methodology. Utilities which do not file FERC Form 1's may use an equivalent source provided the data is prepared in accordance with the FERC Uniform System of Accounts.

Question: Please respond to the assertion that if adopted, the proposal would require investor owned utility (IOU) customers to pay on the basis of projected BPA costs, while BPA would pay the IOU's on the basis of historic costs?

Answer: The assertion is true. BPA's rates are set consistent with statutory directives which require BPA to recover certain costs and use a projected test year to determine those costs for its rates. With the proposed methodology, each IOU's compensation under the exchange would be based on its actual costs.

The purpose of the exchange, however, is to provide wholesale

rate parity between residential and small farm consumers of the IOU's and public agencies. It is not the intent of the proposal to change this purpose.

SALES TO CALIFORNIA

Question: Discuss the progress being made on additional sales of firm power to California.

Answer: BPA has sent a letter to the Pacific Northwest utilities requesting a response from those wishing to participate in a regional sale of firm power to California. Following receipt of the responses, expected in April, the information will be consolidated.

Meetings with the California utilities will then take place to determine if an appropriate sale can be structured and consummated.

BPA also has a number of bilateral marketing discussions in progress with the California utilities. Specifically, discussions are underway between my staff and Southern California Edison regarding a replacement for the existing Exchange Agreement which expires July 31, 1987; a 5-year arrangement which provides for the sale of surplus firm power which has a contract demand of

550 average megawatts; and a 20-year sale of capacity at a contract demand of up to 725 average megawatts with options for additional energy. These might be converted to capacity, energy exchange, or surplus firm power sales.

In addition, we are having discussions with the Los Angeles Department of Water and Power regarding a replacement of the existing Exchange Agreement and an offer of a 2-to-5-year arrangement providing for the sale of surplus firm power at a contract demand of 525 average megawatts.

Discussions with Pacific Gas and Electric Company concerning an extension of the existing arrangement for purchase of seasonal capacity at a contract demand of 600 average megawatts are also continuing. Other preliminary discussions concerning a long-term sale of capacity at a contract demand of 600 average megawatts under terms similar to those with Southern California Edison are also continuing.

INTERTIE SYSTEM

Question: Please describe the option which would increase the capacity of existing transmission lines.

Answer: The option you are referring to is the DC terminal expansion that BPA has under study and which is not included in BPA's FY 1985 Congressional Budget. This project would increase the transfer capacity of the direct-current line terminals at Celilo, Oregon, and Sylmar, California, by 1,100 average megawatts, thus allowing transmission of 3,100 average megawatts of electricity over the line between the two regions. This project would not require the construction of a new transmission line; instead, it would allow use of present unused line capacity. Our study indicates that the project, once begun, could be completed within 3 years.

Question : What is the total estimated cost, Federal share,

construction schedule, and what would be the estimated increase in revenues assuming a 3-64/kWh price?

Answer: The DC terminal expansion projects at Celilo, Oregon, and Sylmar, California are estimated to cost in total between $200-250 million, including about $105 million for upgrading the terminal at Celilo, Oregon. Non-Federal utilities have indicated a willingness to finance the Sylmar terminal project. The Federal share would depend on the extent to which non-Federal utilities participate in the Celilo terminal project. The project could be initiated as early as 1985 if the necessary studies are completed and approvals are received. The project might then be completed and energized in 1988.

If firm sales agreements were made, it is estimated that incremental revenues to the Northwest each year would be approximately $65 million at 34 per kilowatthour, and twice that amount, or about $130 million a year at 6¢ per kilowatthour.

Question: What are the advantages and disadvantages of the terminal expansion option?

Answer: The terminal expansion project could increase intertie capacity 3-5 years earlier than if a new line was constructed because it would utilize the unused capacity of the existing DC Intertie line. Not only does this mean that a new line would not need to be constructed but also that an additional right-of-way would not be required. The project would not depend on the development of interregional firm power contracts but would be justified by increased surplus sales alone. However, the additional capacity would enable more Northwest energy to be sold for longer periods of time and thus enhance the marketability of firm energy which would command a higher price.

The chief disadvantage is that the terminal expansion would not increase interregional transmission reliability since a back-up transmission facility is not in existence to mitigate the impact of outages which may cause the loss of firm load. Design and operating measures would be taken, however, to minimize the occurrence and impact of these potential outages. Terminal independence and redundancy in remedial power system control have been planned.

Another perceived disadvantage of the terminal expansion would be the reduction of justification for a future high capacity line. The construction of a future line would only be undertaken after all the necessary studies are completed, the associated benefits identified, and the appropriate approvals are received.

Question: If agreement is reached on power sales to the Southwest and the terminal expansion is approved, will additional borrowing authority be needed in FY 1985? If so, how do you plan to obtain the additional funding?

Answer: If the terminal expansion was undertaken during

FY 1985, after the appropriate approvals were received, and studies were completed, it could increase BPA's budget obligation of borrowing authority in FY 1985 by up to $65 million, if there were no non-Federal participation. BPA could fund its share of a terminal expansion with proceeds of Treasury borrowings authorized

by the Federal Columbia River Transmission System Act, and could include the debt service on the borrowings in its revenue requirements.

A-76 STUDY

As I understand it, Bonneville has been directed by DOE to study the potential for contracting out a large number of its activities. (OMB Circular A-76)

Question: Can you comment on the scope and cost of the study?

Answer: Pursuant to Government policy, as defined in OMB Circular A-76, each agency is required to develop an inventory of its commercial activities, and to then conduct a management and cost review of each such activitiy. Toward that end, BPA, along with all other elements of the Department, was directed in a February 24, 1984, memorandum to identify, aggregate and schedule for review all of its commercial activities. The Department included a preliminary assessment of BPA's apparent commercial activities with the memorandum.

Based upon the Department's preliminary assessment, approximately 60 percent of BPA's work years in 64 BPA functional areas could be subject to review under Circular A-76. As a result of information requested by the Department and provided by BPA and other DOE elements, the Department is currently refining this preliminary commercial activities inventory assessment. This effort will be complete in the next few weeks.

Resources to perform the studies would vary depending on the size and complexity of each study, as well as the number of activities ultimately included in an agreed-upon final inventory of commercial activities. BPA estimates that conducting A-76 reviews on the Departments' entire preliminary list of BPA activities would require 75 full-time equivalents and $2.8 million annually over a three year period. Some of these amounts might be offset in future years by cost savings identified by the studies.

Question: What has BPA done in the recent past to contract for additional services?

Answer: BPA uses private sources to perform many of its activities. In addition to its existing purchase power contractual agreements, BPA currently spends over $391 million for contractual services. These functions would have required approximately 6,425 in-house FTE. A majority of the contracting is performed in the following areas: Conservation Planning, Acquisition, and Oversight; Nonelectric Power System Operation and Maintenance; ADP Operations and System Development; Fish and Wildlife; and Construction, Testing, and Energization.

BPA has several core activities that must be retained under close BPA operational and policy control. However, BPA recognizes that it has other functions that can be prudently performed with the help of the private sector. The substantial dollar and FTE amounts reflect BPA's use of contracts to perform many of its non-core functions. Based on the historical dollar amount spent during FY 1983, and spending estimates for FY 1984 and 1985,

contracting with private sources has increased and continued increases are expected. In addition, BPA is continuing to evaluate its activities to identify ways to assure the region of an adequate, economical, reliable, efficient, and environmentally acceptable power supply.

FISH AND WILDLIFE ACTIVITIES

Question: Did BPA have any carryover in its FY 1983 fish and wildlife budget? FY 1982? Will BPA have any carryover in its FY 1984 budget? Please describe the reason for any carryovers.

Answer: In FY 1982 BPA budgeted $5.2 million for fish and wildlife protection, mitigation, and enhancement activities. In that year we obligated nearly $4.7 million under contract, largely to the region's fish and wildlife agencies and Indian tribes. FY 1983, we budgeted $10.2 million and obligated over

In

$9.1 million. We are unable to say at this time how much of the $22.1 million budgeted for FY 1984 will eventually be obligated. However, our expectation is that all or most of the available funds will be productively used. BPA does not carry over unobligated funds from one year to the next. Each year's budget is based solely on the summation of activities that reasonably can be expected to be implemented in that fiscal year.

Question: Please describe in more detail BPA's fish and widlife activities, including schedules and budgets, for FY 1985. Provide a breakdown of the operating expenses and capital investment/construction with a full description of each project including total estimated cost and obligations in each year.

Answer: The Fish and Wildlife Program level in the FY 1985 budget before you is $35.3 million. In addition, approximately $58 million in average annual revenues will be foregone due to the firm constraints on the energy generating capability to facilitate downstream passage of juvenile salmon and steelhead. The $35.3 million budgeted includes $8.2 million for the operation and maintenance of the Mitchell Act hatcheries and rearing ponds and $27.1 million to fund BPA's fish and wildlife projects in the Columbia River Basin. Specifically, BPA plans in spend approximately $2.5 million for the five major capital investment projects included in our appropriation language, and about $24.6 million for operating expenses. The operating expenses will be used for the renewal of projects we began funding in previous years or begin funding in FY 1984 and for the initiation of new projects. I have asked my staff to summarize these projects. and will forward the listing to the Committee as quickly as it can be prepared.

Of the five capital investment/construction projects in our FY 1985 appropriation language, three are located in the Yakima River Basin, Washington, the fourth project is on the Umatilla River, Oregon, and the fifth project is near Lake Pend Oreille, Idaho.

When the Planning Council adopted its Fish and Wildlife Program, it created a program section to deal specifically with Yakima River Basin enhancement. This action recognizes the significant contribution the Yakima Basin could make to Columbia